Exploring Carbon Capture Opportunities, Enhanced Oil Recovery, and the Role of Hydrogen as a Clean Fuel
Taha Samaha (MSc, CEng, MIChemE)
LNG & Gas Processing Expert | Process & Flow Assurance Engineer | Chartered Chemical Engineer (CEng, MIChemE) | Operations Readiness | Machine Learning in Process Optimization
Contents
1. Gas conditioning
2. Gas reforming
3. syngas separation
4. Hydrogen-driven gas turbine
5. Enhanced oil recovery
6. CO2/H2 handling
7. References
Gas Conditioning:
Conditioning of gases received from the well depends mainly on the downstream process. For example, if the gas is to be liquefied to LNG, contaminants like H2S, CO2, H2O, and R-SH, have to be removed from the gas stream as these components will freeze in the pipelines and cause other corrosion issues to the carbon steel piping in the downstream equipment. Nitrogen associated with the gas- has to be removed substantially when the gas is being liquefied because the nitrogen dew point is lower than natural gas, thus it is easy to remove by flashing the LNG and the lighter components will strip off. Nitrogen will reduce the heating value of the gas, if present. If the process route changes i.e. going to another petrochemical process, and then treating natural gas will be limited to the removal of sulfur and mercury components due to the other implications on the catalysts in the downstream reactors.
Acid gas removal
Acid gases mainly refer to hydrogen sulfides and Carbone dioxides associated with natural gas. A typical process of acid gas removal is by contacting the feed gas stream with amine, through which an acid-base reaction carried out and produces soluble salts with amine, which in turn regenerated to be get rid of those acid gases, and the process continues. Methyl di-ethanol amine is a common solvent used in this process with a concentration of 40 to 50 %. BASF chemical company supplied activated type of amine (aMDEA) for years to mainly LNG plants.
Another typical process is the absorption of acid gases by glycol. Tri-ethylene glycol process is very selective for acid gas removal process with a high loading rate of carbon dioxide, but it is not useful in the case of cryogenic services as the gas saturates with water from the glycol and then the downstream process overloaded to remove this such amount of water.
For this article, this process is not required as syngas only required, no further cryogenic process is undergoing, but certainly, Sulfur components have to be removed from the gas stream as it will poison the catalyst used in the downstream processes. Sulfur is reducing all sulfur species to hydrogen sulfide over a Cr-Mo catalyst, afterward, the gas passes through another ZnO bed that reduces H2S to very low levels
RSH + H2 è RH + H2S
H2S+ ZnOè H2O+ ZnS
Gas dehydration
This process is carried out mainly for LNG plants and air separation plants. The common process uses molecular sieve and silica gel to adsorb the water content from the gas stream. In methanol or ammonia plants, it is not required to dry the gas.
NGL recovery
The majority of NGL/LPG recovery plants used a traditional arrangement of conventional process equipment for removing heavier hydrocarbons associated with the gas such as scrub column and fractionation. In recent years, Ortloff has developed new, more compact NGL/LPG recovery technology by integrating some of the cooling and fractionation steps within the gas plant for a more compact design and equal or better process performance than traditional ones.
With integrated heat and mass transfer equipment, Ortloff’s different technologies offer several advantages over traditional NGL/LPG recovery arrangements. In addition to its compact, efficient design, it supports operation over the range from 2% to over 98% ethane recovery while maintaining propane recovery at 99% and above.
Different Ortloff’s NGL recovery process is shown below. Each technology is dependent on the size of the facility and the specification of the feed gas.
1)???? Gas subcooled process GSP: Best available technology but with the limitation of loss of some components with the reflux because no recycle back.
2)???? Recycle split-vapor RSV: able to achieve 98% of ethane recovery.
3)???? Overhead recycle OHR: up to 99% of propane recovery can be achieved from this process but with less power than GSP with two columns.
4)???? Single column overhead recycle SCORE: recovery of 99.9% of C3, with only one column and the most common in LNG plants and sales gas
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?Gas reforming:
SMR
The purpose of the catalytic reformation with steam is to extract the maximum quantity of hydrogen contained in the water and the hydrocarbon stream. The reformation of natural gas can be described through two simple reactions.??
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This reaction is strongly endothermic and can be carried out on a suitable catalyst (nickel or noble metals on a substrate material) on an industrial scale at temperatures above 700°?C, therefore the product formation is favored at high-temperature and low pressures, while the shift reaction is exothermic and it is favored at low temperatures and is not affected by pressure changes.
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A high steam-to-carbon ratio raises the natural gas conversion and delivers less methane concentration in the outlet gas, as well as increasing the conversion of CO to CO2. On the other hand, a low steam/carbon ratio impacts positively the costs of the energy required.
In the reformer, SMR, the natural gas and water mixture moves through a series of tubes, each tube contains nickel oxide (NiO) which is the catalyst (the catalyst is very important for the reforming process), where an endothermic reaction occurs and produces a mixture of H2 + CO + CO2 + H2O and this mixture known as synthesis gas.
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In the Reformer, it is required to adjust the Steam / Carbon ratio to prevent the formation of carbon on the catalyst, because breaking the catalyst and blocking of the tube will cause an increase in the load loss through the reformer and decrease its efficiency. The best practice for this ratio is 1:3 i.e. CH4: steam.
High energy is introduced to the reformer (big fired box) is necessary to get the reaction conditions, the residual heat is then used to preheat the feed of natural gas and combustion air in a series of coils installed in the flue gas duct of the reformer.
ATR
For the past decade, the industry’s demand for large-scale production of synthesis gas for Gas-to-Liquids projects has generated a lot of interest in oxygen-blown reforming technology. The oxygen-fired Auto-thermal Reformer (ATR) offers a simple straightforward process layout, where plot area and construction costs are reduced due to the compact design as compared to a tubular reformer. This process comprises syngas production at relatively high temperatures that can be used to generate steam in waste heat recovery boilers to make use of these high temperatures, and pressure ranges between 30 to 40 bars.
The feedstock is mixed with oxygen and steam in a mixer/burner. In the combustion chamber, partial combustion reactions take place, followed by a methane steam reforming reaction and shift conversion to equilibrium over the catalyst bed (NiO).
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The overall reaction is exothermic, resulting in high outlet temperatures. The pressure may be high, up to 100 bar.?In synthesis gas production, a?steam-to-carbon ratio as low as 0.6?is industrially proven.
Coal gasification:
Another process in which coal, steam, and oxygen are burned in a reactor called a gasifier to produce syngas is shown below.?
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?Syngas separation:
There are a set of processes to separate synthesis gas components and dependent on the following:
1.???? End user specifications.
2.???? Seed and supply pressure range.
3.???? Cost, size, and maintenance.
These various separation processes are briefed below:
?I.?? Membrane separation
A typical process uses a Polymer-based membrane and diffusion through the process. The pressure syngas is an important factor for this process to allow high differential pressure across the membrane for the separation to occur. Since this process is the best option for our case in this report, thus I will elaborate in more detail.
Eltron (TM) carbon capture process description: The membrane used is a dense metal alloy with a thin layer of catalyst on each side. A Hydrogen dissociation catalyst is located on the other side, once molecular hydrogen is dissociated, atomic hydrogen diffuses through the dense membrane. Hydrogen partial pressure created by high differential pressure across the membrane drives hydrogen through the membrane pores. The permeate side of the membrane is then removed by the aid of other gas (called sweep gas), or even by the force created by DP to get hydrogen separated. The retentate side of the membrane now contains only the remaining gas (CO2). CO2 is produced at a relatively high pressure which will reduce the compression cost to be used for enhanced oil recovery (EOR). EltronTM developed hydrogen separation membranes for temperature ranges from 250 to 450 C and ~70 bars.
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Key advantage of this process:
·?????? 95% of carbon recovery.
·?????? Maintain CO2 pressure high, this reduces recompression cost for the downstream processes (EOR).
·?????? Applicable for Syngas, regardless of the source of it (natural gas or coal).
·?????? Delivers 99.99% of pure H2.
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II.?? Chemical solvent:
This process is applicable for low partial pressures of CO2 in the gas, and it is all about using solvents that are mainly amine-based that chemically react with CO2 and produce dissolved salts. The desorbed CO2 by amine is then flashed and separated as a gas.
Various solvents used in this regard are BenField (potassium carbonate), methyl ethanol amine (MEA), Methyl di-ethanol amine (MDEA), and Sulfinol. Several companies have the patent of the technology such as UOP, BASF, Lurgi, and Shell.
III.?? Physical sorbent:
The main differences between chemical and physical solvents are the type of bonds between CO2 and solvent. Physical bonds always tend to be weak and the regeneration of the physical solvents requires much less energy than chemical ones. Solvents such as Selexol, Rectisol, and Purisol are widely used and patented by Lurgi or Linde and UOP.
Hydrogen Powered gas turbines:
Heating value: Hydrogen fires lead to combustion temperatures that are higher than conventional natural gas fires, this is because the heating value of Hydrogen is 119 MJ/Kg, and natural gas is 44.8 MJ/Kg. Due to the high reactivity of hydrogen, it improves the firing in the combustors of GT and enhances the propagation of the flame when mixed with other fuels such as natural gas. On the other hand, it helps reduce undesirable emissions and gives low hazardous pollutants.
Emissions and burners: there were several methods used to reduce gas turbine emissions (NOx), the current technology is the dry low NOx burner design. Introducing hydrogen to the gas turbine when comparable to natural gas, it has much larger flammability ranges and lower ignition temperature, thus the premixed burner design will be not suitable as in this case the NOx control will not be attained. Siemens had projected an integrated gasification combined cycle (IGCC) facility in which a hydrogen-powered gas turbine is used to generate power. But, fuel is a mix of CO-H2 with hydrogen concentration ranges from 30 to 40%. The burner design depends on the diffusion of the fuel with a dilution of steam or nitrogen to control. Of course, hydrogen as a fuel will reduce greenhouse gases such as CO2 and CO, but with the high-temperature firing, NOx emission will be difficult to control with the conventional burner design.
GE had started a study of introducing nitrogen to the gas turbine replacing conventional fuel, with the new diffusion burner design it showed that:
·?????? Dilution with the steam will have implications on the enthalpy change of the flue gases across the turbine blades which will impact the blades cooling system, they then simulated the dilution of hydrogen with a massive amount of steam and found that it entails an enhancement of the mixture specific heat, therefore steam as a cheaper media is effective in this case as it improves the efficiency and induces lower overall cost.
·?????? Nitrogen effect on the enthalpy change of the mixture is negligible, consequently it will affect the mass flow rate and this factor in turn will reduce the overall efficiency of the turbine.
Enhanced oil recovery (EOR):
The EOR process is meant by injecting CO2 into a pre-developed oil reservoir where it mixes with oil (reduce oil viscosity due to miscibility of CO2 with oil), this makes the oil freely move to the production wells. After that, CO2 emerges with oil and will be separated in another process in the above-ground facilities.
Oil production from the reservoirs passes through several stages depending on the reservoir's expected inventory and production capacity over the years. The first stage of the well lifetime is called; primary production, which refers to the first instant oil discovery the well is drilled, and oil, and gas will be released with the existing well pressure, at the end of this phase, a considerable amount of oil still trapped between rocks and pores of the reservoir. Water is being injected into the reservoir for the secondary production process, which will sweep the trapped oil into production wells. Water afterward is easily separated from oil as it is not dissolved in oil. By this step, ultimately 50-70 percent of the original oil remains in the reservoir, thus oil field companies tend to inject CO2 at elevated pressure ranges from 90-120 bars into the reservoir and this is the EOR process. CO2 swelled with oil making it lighter, detaching It from the rocks, and causing it to flow freely to the production wells. CO2 miscibility with oil relatively increases with CO2 pressure.
Another advantage of using CO2 for the EOR process is to store CO2 in the depleted oil fields which in turn will contribute to the global efforts to minimize climate change
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Few companies are using this facility to increase well production such as:
Sleipner: The Sleipner project began in 1996 when Norway’s Statoil began injecting more than 1 MTON a year of CO2 under the North Sea.
Salah: In August 2004, Sonatrach, the Algerian national oil and gas company, with partners BP and Statoil, began injecting about 1 million tons per year of CO2 into the geologic formation near their natural gas extraction site in the Sahara Desert.
Rangely: The Rangely CO2 Project has been using CO2 for enhanced oil recovery since 1986.
CO2 compression:
Injecting CO2 into the depleted oil fields requires high pressure (100 bars or above). The injected CO2 into a depth of 1KM or greater ensures CO2 will remain liquid or at the supercritical fluid phase. Thus rocks and pores of the well have to be sealed to avoid CO2 breath though.
It’s helpful to look at the CO2 P-T curve when dealing with high compression ranges. Compression of more than 150 bars is critical to ensure CO2 is water-free because the corrosion tendency becomes very high in the presence of water, and also water freezes at low temperatures; the Critical point of CO2 at 74 bars and 31 C. compression cost reduction is crucial in this case as it will encourage the injection process, so R&D activities focus on developing energy and cost-intensive process for compression.
Compression of below 150 bar can be performed by a multistage reciprocating compressor or turbine-driven compressor. For higher pressure applications can be done by partial compression of CO2, condensing it using a simple liquefaction process, and Pumping it to the reservoir. It is also important to pressure up CO2 above its critical point to avoid corrosion issues for the piping and equipment. Reciprocating machines offer an advantage where process flexibility is important in terms of variations of flows and pressures.
GE company has offered many of those compression solutions with the recent major experience of reinjecting CO2 at ~55,000 Nm3/h and pressure of 480 bars (maximum discharge pressure). In addition, they do have pumping experience of HP centrifugal pumps with a design pressure of 670 bars, which is extremely high and can suit most of the processes.
CO2/H2 handling
Health Precautions
Carbon dioxide, in all its forms, can be used for many purposes. it is important to use its capabilities correctly to achieve the desired effect and eliminate hazards. Our gas specialists can tell you how to do that. Inhalation of CO2 in concentrated form is dangerous to humans. CO2 therefore must not be present in high concentrations in the air. Pressurized CO2 had a risk of exposure to high-pressure services. With CO2 at the critical point, it may liquefy at lower pressure where its temperature tends to be more cryogenic, which if contacted with the skin causes a frostbite.
Hydrogen. Possess the highest flammable gas as it is very reactive and immediately burns when mixed with air as low as 4% of hydrogen (it has a wide combustible range). It is challenging when H2 is stored as it tends to leak due to its small molecular weight.
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